Wellbore fluids containing additives for removing a filter cake and methods of using the same

ABSTRACT

Wellbore servicing fluids and methods of using the same to service a wellbore in a subterranean formation are provided. A filter cake in the wellbore is contacted with the gravel packing fluid, which comprises an oil-soluble additive capable of removing the filter cake. The additive undergoes hydrolysis to produce an acid upon contacting water provided from, for example, water in the wellbore servicing fluid, connate water in the subterranean formation, water in the filter cake, water produced by the subterranean formation, water pumped into the wellbore, or combinations thereof. The acid dissolves particulates in the filter cake in situ. In an embodiment in which the wellbore servicing fluid serves as a gravel packing fluid, the fluid also deposits gravel along the face of the subterranean formation, forming a barrier against the migration of sand from the formation and into the wellbore.

FIELD OF THE INVENTION

This invention generally relates to wellbore servicing fluids andmethods of using the same. More specifically, the invention relates tomethods of servicing a wellbore in contact with a subterranean formationusing a fluid containing an oil soluble additive for removing a filtercake from the face of the subterranean formation.

BACKGROUND OF THE INVENTION

Natural resources such as gas, oil, and water residing in a subterraneanformation can be recovered by drilling wells into the formation. Welldrilling involves drilling a wellbore down to the formation whilecirculating a drilling fluid or mud through the wellbore. Various typesof drilling fluids, also known as drill-in fluids when used in theproductive interval, have been used in well drilling, such aswater-based fluids, mineral oil-based fluids, and synthetic oil-basedfluids. Such drilling fluids form a thin, slick filter cake on theformation face that provides for successful drilling of the wellbore andthat helps prevent loss of fluid to the subterranean formation.

Several stages may be used to produce oil found in subterraneanformations. The first stage, which is known as the primary productionstage, allows the oil to flow into a production well (or wells) undernatural forces. At first, the natural forces may be sufficient to drivethe oil to the surface where it is recovered. However, at some point,pumps may be required to displace the oil from the wellbore to thesurface. The primary production stage usually yields only about 5% to15% of the oil in the reservoir. A secondary recovery operation thus istypically performed to recover additional amounts of the oil from thereservoir. A common secondary recovery operation known as secondaryflooding involves injecting a fluid such as water into a so-calledinjection well (or wells) to drive oil in the formation to theproduction well (or wells). Secondary flooding usually recovers up to anadditional 50% of the original oil in the reservoir. Tertiary recoveryoperations such as tertiary flooding may also be used to drive theremaining oil from the formation to the production well. Unfortunately,the presence of the filter cake on the face of the subterraneanformation can adversely affect the flow of fluid though the injectionwells and the production wells. In the case of the injection wells,particularly in deepwater environments, the injected fluid is not flowedback to remove the filter cake left by the drill-in fluid. The pumppressures (e.g., fracturing pressures) required to inject past thefilter cake are higher than desirable for achieving good sweepefficiency of the oil.

Many subterranean formations are unconsolidated or poorly consolidated.Thus, loose sand grains may undesirably flow into an adjacent productionwell, contaminating the fluid being recovered from the well. The sandcould cause severe erosion of well equipment and could plug the flowpassages into the well such that an expensive workover of the well isrequired. One method commonly utilized to prevent migration of sand intowells and to maintain the integrity of subterranean formations is a wellcompletion method known as gravel packing. In gravel packing, apermeable screen is placed against the face of a subterranean formation,followed by packing gravel against the exterior of the screen. The sizeof the gravel particles used for this purpose are larger than the sandparticles but are also small enough to ensure that sand cannot passthrough voids between the particles. The gravel is typically carried tothe subterranean formation by suspending the gravel in a so-calledgravel packing fluid and pumping the fluid to the formation. The screenblocks the passage of the gravel but not the fluid into the subterraneanformation such that the screen prevents the gravel from being circulatedout of the hole, which leaves it in place. The gravel is separated fromthe fluid as the fluid flows through the screen leaving it deposited onthe exterior of the screen. Fluid leakoff into the formation matrix canalso result in the sand being placed around the screen.

Once an open hole wellbore or interval has been drilled to penetrate asubterranean formation, the filter cake cannot be removed from the faceof the formation before gravel packing the formation. Otherwise, anexcessive amount of fluid containing sand could pass from the formationinto the wellbore while attempting to remove the filter cake. Horizontalwellbores are particularly limited in this respect because they aretypically thousands of feet in length and thus have a relatively largesurface area through which fluid can pass. Further, using an acid washto remove the filter cake after the gravel has been placed in the wellis usually not an option due to the excessive cost involved combinedwith the inherent difficulty in placing acid uniformly across the entireinterval without excessive leak-off of the acid into the localized areasalong the wellbore, particularly in horizontal completions. In postdrilling acidizing, an additional risk of damaging the formation fromthe spent or partially spent acid leaking off into the formation exists.A need therefore exists for relatively inexpensive methods of removing afilter cake from a subterranean formation without risking the loss ofsubstantial amounts of potentially damaging fluid into the formation.

SUMMARY OF THE INVENTION

In an embodiment, wellbore servicing fluids include an additive that iscapable of removing a filter cake from a face of a subterraneanformation penetrated by a wellbore. The wellbore servicing fluids may beoil-based fluids, invert emulsion fluids, or reversible emulsion fluids.The additive for removing the filter cake is dissolved in the oil phaseof the wellbore servicing fluids. The additive is capable of undergoinghydrolysis to produce an acid when it comes in contact with water. Theacid produced by the additive is capable of dissolving particulates inthe filter cake such as calcium carbonate particulates. It is alsocapable of converting a reversible water-in-oil emulsion of the filtercake to an oil-in-water emulsion for facilitating removal of the filtercake. The wellbore servicing fluid may be, for example, a gravel packingfluid, a drilling fluid, a completion fluid, a displacement fluid, or awork-over fluid.

In another embodiment, methods of servicing a wellbore in a subterraneanformation include providing the foregoing wellbore servicing fluidcomprising an additive for removing a filter cake from the formation,followed by contacting the filter cake with the fluid. Such a filtercake is formed on the face of the subterranean formation while using adrilling fluid to drill a wellbore that penetrates the subterraneanformation. The additive undergoes hydrolysis to produce an acid uponcontacting water provided from, for example, water in the wellboreservicing fluid, connate water in the subterranean formation, water inthe filter cake, water produced by the subterranean formation, waterpumped into the wellbore, or combinations thereof. The created aciddissolves particulates in the filter cake. In addition to removing thefilter cake from the subterranean formation, the gravel packing fluidalso deposits gravel along the face of the subterranean formation,forming a barrier against the migration of sand from the formation andinto the wellbore.

DETAILED DESCRIPTION OF THE PREFERRED EMBODIMENTS

In an embodiment, a wellbore servicing fluid comprises at least oneadditive capable of removing a filter cake from the face of asubterranean formation. The filter cake builds up on the formation faceduring the drilling of a wellbore that penetrates the formation. Thefilter cake can be removed by contacting it with the wellbore servicingfluid. As used herein “wellbore servicing fluid” refers to a fluid usedin drilling, gravel packing, and/or work-over applications such as adrilling fluid, a gravel packing fluid, a completion fluid, adisplacement fluid, and a work-over fluid, all of which are well knownin the art.

The additive employed in the gravel packing fluid is an oil-solublecompound that undergoes hydrolysis to produce acid in the presence of ahydroxide ion such as the hydroxide ion formed by water, wherein theacid is capable of dissolving particulates in the filter cake such ascalcium carbonate particulates. Hereinafter, the additive will bereferred to as an oil-soluble additive (OSA). If the filter cake isformed from a reversible emulsion drilling fluid, the acid produced bythe OSA is also capable of converting a water-in-oil emulsion in thefilter cake to an oil-in-water emulsion that can be more easily cleanedas will be described later in more detail. Examples of OSA's include,but are not limited to, organic anhydrides such as acetic anhydride,glycols, and esters, all of which form organic acid when hydrolyzed. Byway of example, acetic anhydride forms acetic acid when it ishydrolyzed, as demonstrated by the following chemical equation:(CH₃CO)₂O+H₂O→2CH₃COOHThe amount of OSA in the wellbore servicing fluid is preferably in therange of from about 0.1 weight % (wt. %) to about 25 wt. % by totalweight of the wellbore servicing fluid, more preferably from about 5 wt.% to about 10 wt. %.

The liquid of the wellbore servicing fluid contains an oil phase inwhich the OSA is dissolved. Examples of suitable liquids for the gravelpacking fluid include, but are not limited to, an oil-based fluid, aninvert emulsion fluid (i.e., a water-in-oil type emulsion), and areversible emulsion fluid (i.e., a fluid that can be readily andreversibly converted from a water-in-oil emulsion to an oil-in-wateremulsion), with the reversible emulsion fluid being preferred. An invertemulsion fluid and a reversible emulsion fluid in its water-in-oil statecontain a continuous phase of oil and a discontinuous phase of water,wherein the discontinuous phase, also known as the dispersed phase,forms a stable dispersion of fine droplets throughout the continuousphase. A suitable commercially available invert emulsion fluid is theBROMIMUL invert emulsion fluid manufactured by Halliburton EnergyServices, Inc. The oil in the gravel packing fluid may be, for example,petroleum oil, natural oil, synthetically derived oil, or combinationsthereof. Preferably, the oil is an alpha olefin, an internal olefin, adiester of carbonic acid, a paraffin, kerosene oil, diesel oil, mineraloil, or combinations thereof. In embodiments where the liquid is aninvert emulsion fluid or a reversible emulsion fluid, the watercontained therein may be, for example, municipal treated or fresh water,sea water, naturally-occurring brine, a chloride-based, bromide-based,or formate-based brine containing monovalent and/or polyvalent cations,or combinations thereof. Examples of chloride-based brines includesodium chloride and calcium chloride. Examples of bromide-based brinesinclude sodium bromide, calcium bromide, and zinc bromide. Examples offormate-based brines include sodium formate, potassium formate, andcesium formate. When the wellbore servicing fluid is an invert emulsionfluid or a reversible emulsion fluid, it may contain from about 30 wt. %to about 50 wt. % oil and from about 50 wt. % to about 70 wt. % water,all weight percentages being based on the total weight of the wellboreservicing fluid.

In an embodiment in which the wellbore servicing fluid is a gravelpacking fluid, the fluid comprises a liquid with gravel suspendedtherein and the additive described above. The gravel packing fluid canbe used to perform in situ removal of the filter cake and deposition ofgravel on the wellbore wall. The gravel forms a barrier to the passageof formation sand-containing fluids that could otherwise exit thesubterranean formation. As such, the filter cake can be removed beforesubstantial amounts of formation sand-containing fluids are lost fromthe subterranean formation. The gravel used in the gravel packing fluidcomprises solid particles that can be suspended in the gravel packingliquid. The median size of the gravel particles are larger in diameterthan the median particle size of the subterranean formation sand.Preferably, the median size of the gravel particles are also smallenough to ensure that the formation sand particles cannot pass throughthe openings between the gravel particles once the gravel particles havebeen deposited on the wellbore wall or within perforation tunnels.Examples of materials that may be used to form the gravel include, butare not limited to, graded siliceous sand, spherical glass beads,ceramic materials, and bauxite. Any of the foregoing materials may becoated with one or more thermally activated phenolic resins, epoxycompounds, and/or tackifiers. The amount of gravel in the gravel packingfluid preferably ranges from about 0.1 pound of gravel/gallon of fluidto about 15 pounds of gravel/gallon of fluid, more preferably about 4pounds of gravel/gallon of fluid.

Optionally, the wellbore servicing fluid may contain a polymer breakerto assist the OSA in the removal of polymer-containing filter cakes.Examples of suitable polymer breakers include, but are not limited to,oxidants and enzymes. Suitable polymer breakers are disclosed inInternational Publication No. WO 00/57022, which is incorporated byreference herein.

As described previously, the wellbore servicing fluid may serve asvarious types of fluids and thus may include additional additives asdeemed appropriate by one skilled in the art. For example, it would beunderstood by one skilled in the art that a gravel packing fluid couldcomprise surfactants, emulsifiers, non-emulsifiers, wetting agents,organophilic clays, viscosifiers, weighting agents, bridging agents,fluid loss control agents, oxidizing agents, iron control additives, pHbuffers, and scale inhibitors. It is preferred that any additionalmaterials do not interfere with the reversibility of the fluid.

The steps used to prepare an invert emulsion fluid/reversible emulsionfluid for use in the wellbore servicing fluid would be apparent to oneskilled in the art. For example, a desired quantity of an oleaginousfluid may be mixed with a suitable amount of an emulsifier, followed byadding the desired amounts of water and any other additives whilecontinuously mixing.

In embodiments in which the wellbore servicing fluid is a reversibleemulsion, the fluid can be readily and reversibly converted from awater-in-oil emulsion to an oil-in-water emulsion by increasing thehydrogen ion concentration of the fluid. The hydrogen ion concentrationmay be increased by contacting the fluid with an effective amount of anacid to cause its conversion. One or more amine emulsifiers present inthe fluid are protonated by the hydrogen ions. The resulting protonatedamine has a cationic charge that increases its water and acidsolubility. As a result, the fluid now favors a water external emulsionstate.

The steps used to prepare the wellbore servicing fluid for use inservicing a wellbore that penetrates a subterranean formation would beapparent to one skilled in the art. The different components in thewellbore servicing fluid can be combined at the drilling site prior toits use. For example, the preparation of a gravel packing fluid mayentail vigorously mixing a desired quantity of the liquid being usedwith a suitable amount of the OSA, followed by adding a suitable amountof gravel to the liquid. As a result, the OSA becomes dissolved in theoil-phase of the liquid, and the gravel becomes suspended in the liquid.The OSA and the gravel can be added to the liquid in any sequentialorder or at the same time. In an embodiment, the OSA is added to theliquid before the addition of the gravel.

In an embodiment, the wellbore servicing fluid may be used to gravelpack a subterranean formation. The gravel packing may be performed byfirst moving a permeable screen, e.g., a wire mesh screen, into awellbore and placing the screen adjacent to the face of a subterraneanformation penetrated by the wellbore. The screen contacts a filter cakethat has formed on the formation face as a result of drilling thewellbore using a drilling fluid such as a reversible emulsion fluid. Theforegoing gravel packing fluid containing the OSA is then pumped intothe wellbore in such a manner that it contacts the filter cake and thescreen on the face of the subterranean formation. The OSA undergoeshydrolysis, thus forming an acid that dissolves particulates such ascalcium carbonate particulates in the filter cake. In one embodiment,when subjected to downhole temperatures the OSA may react with, ifpresent, water in the fluid itself, connate water in the subterraneanformation, water in the filter cake, water produced by the subterraneanformation, and/or water pumped into the wellbore. A gravel packapparatus that may be used in conjunction with the gravel packing fluiddescribed herein is disclosed in U.S. Pat. No. 5,960,879, which isincorporated by reference herein in its entirety.

In another embodiment, a completion or displacement fluid containing theOSA can also be utilized in an open wellbore having a screen, e.g., aconventional wire wrapped screen, a pre-packed wire wrapped screen, or apremium filter media for sand control, but no gravel pack. The fluid mayserve to remove a filter cake in the same manner as described above. Acompletion fluid containing the OSA may be circulated into place oncethe screen completion assemblies are in place across the open holeinterval. A displacement fluid containing the OSA may be used for thedisplacement of the drilling fluid from the open hole once an expandablescreen is placed across the formation face. The methods by which theforegoing wellbore servicing fluid may be used in other applicationssuch as in drilling and work-over applications would be apparent to oneof ordinary skill in the art.

The wellbore servicing fluid is particularly useful in removing a filtercake formed from a reversible emulsion drilling fluid. Without intendingto be limited by theory, it is believed that the mechanism by which thewellbore servicing fluid removes the filter cake is that the acidproduced by the OSA causes the oil in the filter cake to change from thecontinuous phase to the discontinuous phase and the water in the filtercake to change from the discontinuous phase to the continuous phase. Asa result of this conversion, the oil-wet particles of the filter cakebecome water-wet, allowing the acid to readily reach and dissolve theacid soluble particulates, e.g., the calcium carbonate particulates, inthe filter cake. Thus, filter cakes formed from a reversible emulsiondrilling fluid typically can be removed more effectively and rapidlyusing the wellbore servicing fluid described herein than those formedfrom a non-reversible drilling fluid.

When the wellbore servicing fluid serves as a gravel packing fluid, itnot only removes the filter cake, it also concurrently deposits gravelon the exterior of the screen adjacent to the face of the subterraneanformation. In particular, the gravel in the fluid is filtered by thescreen as the fluid passes through the screen to the subterraneanformation. In this manner, the gravel becomes sufficiently packed on theexterior of the formation to form a barrier to sand that could otherwisepass from the subterranean formation into the wellbore. That is, theopenings between the gravel particles are small enough to prevent thesand from passing therethrough. As a result, the gravel filters the sandfrom the fluids that exit the subterranean formation and pass into thewellbore during production. Removal of the filter cake may continue insitu after the gravel has been deposited on the face of the subterraneanformation.

Examples

The invention having been generally described, the following examplesare given as particular embodiments of the invention and to demonstratethe practice and advantages hereof. It is understood that the examplesare given by way of illustration and are not intended to limit thespecification or the claims to follow in any manner.

Comparative Example 1

A filter cake was formed using the following static filtration test. Acalcium carbonate weighting material was prepared by mixing 1 partBARACARB 5 weighting material with 3 parts BARACARB 25 weightingmaterial, both of which are sold by Baroid Industrial Drilling Products,Inc. About 500 milliliters (mL) of an oil-based mud (OBM), i.e., adiesel-based mud recovered from a test well site, were then blended with10 pounds per gallon (ppg) of the calcium carbonate weighting material.Approximately 200 mL of the resulting OBM mixture were placed on aporous ceramic disc (35 micron) of a high-temperature high pressure(HTHP) cell. The ceramic disc was then placed in a heat jacket having atemperature of 170° F. and connected to a pressure source. Nitrogenpressure (500 psig) was applied to the HTHP cell while measuring thefiltrate volume passing through the porous ceramic disc. The filtratevolume was monitored at time intervals ranging from 1 minute to 10minutes for a duration of 1 hour after which time the HTHP cell remainedunder pressure overnight (approximately 12 to 24 hours). The filtratevolume was measured to be 1 mL after 30 minutes and 21 mL after 15hours. As a result of the removal of liquid from the OBM mixture, afilter cake having a uniform thickness of about 2 mm formed on theporous ceramic disc. The fluid removed from the HTHP cell was flowableand appeared to be similar to the original OBM.

Example 1

The static filtration test was performed in the same manner as describedin Comparative Example 1 except that 10 weight % of an acetic anhydrideOSA was blended with the OBM before placing it on the porous ceramicdisc. Nitrogen gas undesirably began to bypass around the perimeter ofthe filter cake sometime overnight. The filtrate volume was measured tobe 2.5 mL after 30 minutes and 31.5 mL after 15 hours. The fluid removedfrom the HTHP appeared to be highly viscous with a consistency like thatof peanut butter. It had to be scooped from the cell. No filter cake wasobserved.

Example 2

The static filtration test was performed in the same manner as describedin Comparative Example 1 except that the HTHP cell was kept underpressure only for 30 minutes. The filtrate volume was measured to be 1.4mL after 30 minutes. A filter cake having a uniform thickness of about 1mm was formed. The fluid removed from the HTHP cell appeared to besimilar to the original OBM.

A filter cake removal test was then performed by placing approximately200 mL of a mixture of BROMIMUL invert emulsion fluid containing 10weight % OSA by weight of the fluid in the HTHP cell containing theresidual OBM filter cake. Nitrogen pressure (500 psig) was again appliedto the HTHP cell. The subsequent fluid loss and cleanup characteristicsof the above mixture were observed. The volume of mixture that hadpassed through the porous ceramic disc after 60 minutes was measured tobe 8.2 mL. The fluid removed from the HTHP cell appeared to betranslucent and amber in color. The filter cake appeared to become looseand delaminated during this time. It was also entrained with gas bubblessuch that its appearance was similar to rising bread dough, indicatingacid dissolution of the calcium carbonate particles contained within theOBM filter cake.

Example 3

A test was also performed to examine the degree of reaction of an OSAwith calcium carbonate. First, BROMIMUL invert emulsion fluid wasblended with 10 pounds of BARACARB 25 calcium carbonate (aweighting/fluid loss control material) per gallon of the fluid. Then 10weight % of an OSA by total weight of the BROMIMUL/BARACARB 25 mixturewas added to the mixture. Transmitted plane and polarized lightmicroscopy was performed using a BH2 microscope manufactured by OlympusAmerica, Inc to observe both the emulsion character and the reactivityof the calcium carbonate throughout a four day period at roomtemperature and a two day period at 170° F. Hydrolysis of the OSA wasinitially inhibited because not enough water was in direct contact withthe OSA due to a physical barrier created by the OSA being containedwithin the external oil phase of the BROMIMUL invert emulsion fluid.Free water was then added to the mixture. Upon addition of the freewater, the OSA produced an acid that reacted with the calcium carbonate.This example illustrates that, if desired, the reaction of the OSA afterit has been placed downhole may be delayed until free water has beenpumped downhole.

The foregoing diesel-based OBM showed desired behavior. The BROMIMULinvert emulsion fluid performed better than the diesel-based OBM in thatits viscosity did not increase significantly during the staticfiltration test. Using a gravel packing fluid containing a BROMIMULinvert emulsion fluid and an OSA may be a viable approach to achievingintegral filter cake clean-up without compromising short-term fluid lossprotection.

While the preferred embodiments of the invention have been shown anddescribed, modifications thereof can be made by one skilled in the artwithout departing from the spirit and teachings of the invention. Theembodiments described herein are exemplary only, and are not intended tobe limiting. Many variations and modifications of the inventiondisclosed herein are possible and are within the scope of the invention.Use of the term “optionally” with respect to any element of a claim isintended to mean that the subject element is required, or alternatively,is not required. Both alternatives are intended to be within the scopeof the claim.

Accordingly, the scope of protection is not limited by the descriptionset out above, but is only limited by the claims which follow, thatscope including all equivalents of the subject matter of the claims.Each and every claim is incorporated into the specification as anembodiment of the present invention. Thus the claims are a furtherdescription and are an addition to the preferred embodiments of thepresent invention. The discussion of a reference in the Description ofRelated Art is not an admission that it is prior art to the presentinvention, especially any reference that may have a publication dateafter the priority date of this application. The disclosures of allpatents, patent applications, and publications cited herein are herebyincorporated by reference, to the extent that they provide exemplary,procedural or other details supplementary to those set forth herein.

1. A method of servicing a wellbore in a subterranean formation,comprising: (a) providing a wellbore servicing fluid comprising anadditive for removing a filter cake from a face of the subterraneanformation; and (b) contacting the filter cake with the additive tothereby remove the filter cake.
 2. The method of claim 1, wherein theremoval of the filter cake and the servicing of the wellbore areperformed in situ.
 3. The method of claim 1, wherein the wellboreextends in a horizontal direction.
 4. The method of claim 1, wherein thewellbore servicing fluid comprises gravel suspended therein, wherein thegravel is deposited in the wellbore concurrent with the removal of thefilter cake.
 5. The method of claim 1, wherein the wellbore servicingfluid is selected from the group consisting of an oil-based fluid, aninvert emulsion fluid, and a reversible emulsion fluid.
 6. The method ofclaim 5, wherein the additive is dissolved in an oil phase of thewellbore servicing fluid.
 7. The method of claim 1, wherein the additiveis an oil-soluble compound that undergoes hydrolysis in the wellbore toproduce an acid.
 8. The method of claim 7, wherein the acid dissolvesparticulates in the filter cake.
 9. The method of claim 8, wherein theparticulates comprise calcium carbonate.
 10. The method of claim 7,wherein the filter cake is formed from a reversible water-in-oilemulsion.
 11. The method of claim 10, wherein the acid converts thereversible water-in-oil emulsion of the filter cake to an oil-in-wateremulsion.
 12. The method of claim 7, wherein the additive undergoeshydrolysis when it contacts water provided from water in the wellboreservicing fluid, connate water in the subterranean formation, water inthe filter cake, water produced by the subterranean formation, waterpumped into the wellbore, or combinations thereof.
 13. The method ofclaim 7, wherein the additive comprises organic anhydrides, glycols,esters, or combinations thereof.
 14. The method of claim 7 wherein thewellbore servicing fluid further comprises a polymer breaker.
 15. Themethod of claim 1, wherein an amount of the additive present in thewellbore servicing fluid ranges from about 0.1% to about 26% by totalweight of the fluid.
 16. The method of claim 4 wherein an amount of thegravel present in the wellbore servicing fluid ranges from about 0.1 toabout 15 pounds of gravel/gallon of the fluid.
 17. The method of claim5, wherein the wellbore servicing fluid comprises from about 30% toabout 50% oil and from about 50% to about 70% water when the fluid is aninvert emulsion fluid or a reversible emulsion fluid, all weightpercentages being by total weight of the wellbore servicing fluid.
 18. Awellbore servicing fluid comprising an additive that is capable ofremoving a filter cake from a face of a wellbore in a subterraneanformation.
 19. The wellbore servicing fluid of claim 18, being capableof performing in situ removal of the filter cake and servicing of thewellbore.
 20. The wellbore servicing fluid of claim 18, wherein thewellbore extends in a horizontal direction.
 21. The wellbore servicingfluid of claim 18, further comprising gravel suspended therein.
 22. Thewellbore servicing fluid of claim 18, wherein the fluid is selected fromthe group consisting of an oil-based fluid, an invert emulsion fluid,and a reversible emulsion fluid.
 23. The wellbore servicing fluid ofclaim 22, wherein the fluid comprises an oil phase in which the additiveis dissolved.
 24. The wellbore servicing fluid of claim 18, wherein theadditive is an oil-soluble compound capable of undergoing hydrolysis toproduce an acid.
 25. The wellbore servicing fluid of claim 24, whereinthe acid is capable of dissolving particulates in the filter cake. 26.The wellbore servicing fluid of claim 25, wherein the particulatescomprise calcium carbonate.
 27. The wellbore servicing fluid of claim24, wherein the acid is capable of converting a reversible water-in-oilemulsion in the filter cake to an oil-in-water emulsion.
 28. Thewellbore servicing fluid of claim 18, wherein the additive comprisesorganic anhydrides, glycols, esters, or combinations thereof.
 29. Thewellbore servicing fluid of claim 18, further comprising a polymerbreaker.
 30. The wellbore servicing fluid of claim 18, wherein an amountof the additive present in the fluid ranges from about 0.1% to about 25%by total weight of the fluid.
 31. The wellbore servicing fluid of claim21, wherein an amount of the gravel present in the fluid ranges from 0.1to about 15 pounds of gravel/gallon of the fluid.
 32. The wellboreservicing fluid of claim 22, comprising from about 30% to about 50% oiland from about 50% to about 70% water when the fluid is an invertemulsion fluid or a reversible emulsion fluid, all weight percentagesbeing by total weight of the wellbore servicing fluid.